Method of separating components from produced oil sands

ABSTRACT

A method of separating solids and hydrocarbons from oil sands material has the steps of: mixing the oil sands material with water to create an oil sands slurry, the oil sands slurry comprising hydrocarbons, sand, water and a bubbling agent, the oil sands slurry being free from added surfactants, the bubbling agent comprising metal compounds present in the oil sands material that act as a catalyst; and conditioning the oil sands slurry such that: the bubbling agent produces bubbles within the oil sands slurry; at least a portion of the sand settles out from the oil sands slurry; and the bubbles interact with the hydrocarbons to produce a hydrocarbon froth at a top of the oil sands slurry. Metal compounds may be extracted from the oil sands slurry to be reused as a catalyst or as a source of revenue.

TECHNICAL FIELD

This relates to a method of extracting components from oil sands material, and in particular, separating components such as sand, metal compounds, hydrocarbons and water from a slurry formed from oil sands material.

BACKGROUND

Surface mining of oil sands ore in Ft. McMurray Alberta and other locations around the globe require extremely high capital and operating costs. Some of the mining extraction challenges that increase costs including incomplete recovery of the bitumen from the sands, difficult solids contaminations, high energy costs, and a large emulsified waste stream. The waste stream requires large tailings ponds to hold an accumulating volume which has to-date not been successfully treated. The growing waste tailings ponds are toxic mainly due to salts, residual hydrocarbons and naphthenic acids. In addition a large amount of precious metals are bound in the waste tailings emulsion and industry has not yet found an affordable method to extract them.

The current heavy oil industry is also burdened with high CO₂ emissions and a large carbon footprint due to its intense energy use and complex massive equipment infrastructure. Methane and CO₂ emissions from the tailings ponds compound this problem.

Another concern is that the challenges of treating tailings waste emulsion results in a loss of a large volume of process water. Industry currently recycles a small amount of surface water from the tailings ponds. This recovered water can only be used for a few process cycles due to a high concentration of salts and naphthenic acids.

Ongoing research focuses on confronting these issues in order to reduce costs and the impact on the environment.

U.S. Pat. No. 7,678,201 (Cobb) entitled “Composition and process for the removal and recovery of hydrocarbons from substrates” is an example of a method for separating hydrocarbons from a contaminating material.

SUMMARY

According to an aspect, there is provided a method of separating components in oil sands material, such as sand, metal compounds, and hydrocarbons, the method comprising the steps of mixing the oil sands material with water to create an oil sands slurry, the oil sands slurry comprising hydrocarbons, sand, water and a bubbling agent, the oil sands slurry being free from added surfactants, and conditioning the oil sands slurry such that: the bubbling agent reacts to produce bubbles within the oil sands slurry, at least a portion of the sand settles out from the oil sands slurry, and the bubbles interact with the hydrocarbons to produce a hydrocarbon froth at a top of the oil sands slurry.

According to other aspects, the method may comprise one or more of the following features, along or in combination: the bubbling agent may comprise an oxidant that is added to the oil sands slurry and reacts with a catalyst in the oil sands slurry; the bubbling agent may comprise a catalyst added to the oil sands slurry; metal compounds may be present in the oil sands material; at least a portion of the metal compounds may be catalyst material and the bubbling agent may comprise catalyst material present in the oil sands material; a portion of the metal compounds may settle out from the oil sands slurry with the at least a portion of the sand; a portion of the metal compounds may be carried within the hydrocarbon froth; at least a portion of the metal compounds carried within the hydrocarbon froth may be recovered from the oil sands material; a portion of the recovered metal compounds may be catalyst material and the method may further comprising the steps of conditioning the catalyst material and mixing the conditioned catalyst material with the oil sands slurry, the hydrocarbon froth, water recovered from the oil sands slurry, or combinations thereof; the method may further comprise the steps of transferring the hydrocarbon froth to a treatment vessel, causing the froth to release gas, adding an oxidant to the treatment tank and reducing the pH of the hydrocarbon froth to between around 4 to 6, and causing the oxidant to react with the froth to produce a phase of liquid hydrocarbons from the froth; the metal particles may act as a catalyst for the oxidant in the treatment tank; conditioning the oils sands slurry may comprise maintaining the pH at or below a neutral level and maintaining a temperature of at least 40° C.; the oils sands slurry may be at least partly heated by exothermic reactions of the bubbling agent; the method may further comprising the step of injecting air bubbles into the oil sands slurry to enhance the generation of the hydrocarbon froth; and the oil sands slurry may be substantially free from sodium ions.

According to other aspects, a physicochemical reaction in a separation unit may extract the bitumen froth and removes the sand in a rapid separation reaction. In the separation unit, it may be important to prevent aggressive mixing in the separation unit which can cause the dispersion of an unnecessary amount of clay fines into the bitumen froth. Instead, the separation unit may be designed to promote increased retention time for the sand to fall to allow for more bubble cleaning of the sand. Once separated, sand may be transferred to a standard sand cleaning unit that separates heavy material such as iron metals and removes water. Departure of a large weight (e.g. possibly around 80% of the ore) and volume of the sand will generally simplify the remainder of the extraction process. An oxidant may be added to the slurry when it enters the reaction vessel that produces micro and nano-bubbles in numerous reactions. Hydrogen peroxide may be added as the oxidant, which may then be decomposed by several compounds natively present in the oil sands ore. Maintaining a neutral pH in the reaction vessel may promote a rapid decomposition of hydrogen peroxide to water and oxygen bubbles. A range of other Reactive Oxygen Species (ROS), or combinations thereof, may be used as oxidants. If used, the amount of hydrogen peroxide may be between about 0.25% to about 1.5% by volume of the oil sands slurry. In some cases, the amount of oxidant added may be reduced or avoided if the oil sands ore has a sufficiently high catalyst content, such as pyrite, or if the slurry is supplemented with suitable catalysts from an external source. In such a case, a reaction in the slurry may be catalyzed by maintaining suitable conditions, such as sufficient aeration and by maintaining an optimized pH. For example, with suitable conditions maintained, pyrite (or other suitable compounds) may act as a catalyst to produce oxygen bubbles & hydrogen peroxide, where the peroxide quickly decomposes to oxygen and water in the presence of iron species. The pH of the oil sands slurry may need to be neutral or below neutral for these reactions to occur, such as to produce optimal amounts of ROS and/or a high volume of bubbles. The bubbles created by reactions within the ore material may agitate the materials in the slurry to promote separation of hydrocarbons from the sand and clay in the ore. In addition, the bubbles may carry the bitumen to the surface of the slurry to create a hydrocarbon froth that can then be separated from the vessel for further processing. The decomposition of ROS, such as hydrogen peroxide, may be an exothermic reaction that may be used to raise the temperature of the slurry in the insulated reactor vessel, such as to a temperature range of between about 60° C. and about 70° C. The optimal temperature range may depend on the composition of the oil sands slurry. In some cases, the ROS reactions may provide the majority of the heat energy needed in the separation vessel. The rate of reaction may be controlled by lowering the pH. In addition to bubbles generated by reacting ROS, bubbles may be introduced into the separation vessel. A vapour extractor may remove gases above the froth launder area and reintroduce the gases to the bubble aeration device, which may be located at or toward the bottom of the primary reactor vessel. In some cases, it may be possible to extract over 99% of the hydrocarbons from the oil sand ore, leaving behind relatively clean sand that is suitable for reclamation, and oil sand process water that is sufficiently clean to be economically viable to recycle.

According to an aspect, there is provided a method of separating a liquid hydrocarbon phase from a hydrocarbon froth, the method comprising the steps of, in a treatment vessel, controlling a pH of the hydrocarbon froth to cause the hydrocarbon froth to react with an oxidant in the presence of a catalyst to break a water-hydrocarbon emulsion within the hydrocarbon froth.

According to other aspects, the method may comprise one or more of the following features, alone or in combination: controlling the pH may comprise reducing the pH of the hydrocarbon froth; the method may further comprise the step of reducing a gas phase of the hydrocarbon froth prior to or simultaneously with causing the hydrocarbon froth to react with the oxidant; the pH may be reduced to between around 4 and 6, such as by adding an acid, such as an acid that is free from sulphur; the method may further comprise the step of heating the hydrocarbon froth; the hydrocarbon froth may comprise fine solids such as pyrite, and at least a portion of the catalyst may comprise pyrite; hydrocarbons, water, and solids may be separated from the reacted hydrocarbon froth; the catalyst may comprise a least portion of the separated solids that are recycled into the treatment tank; the separated hydrocarbons may be mixed with a diluent to form a hydrocarbon diluent mixture and any remaining solids may be separated from the hydrocarbon diluent mixture in a centrifugal separator.

According to other aspects, froth treatment may comprise a series of Fenton-like oxidation reactions in a low pH reactor vessel. To reduce the pH to a preferred operating range, such as between about 4 and 4.5, a non-sulphur acid, or an acid without any sulphur, may be added, such as acetic acid, peracetic acid, and/or CO₂ bubbles. The oxidant may be a number of different ROS such as hydrogen peroxide, peracetic acid or ozone. The volume of oxidant required may vary based on the compound profile of the ore of each different mine site. Catalysts may be selected from among some of the compounds extracted and processed from the same oil sands ore. Large volume catalysts that may be available in the oil sands ore include: anatase, rutile, magnetite, hematite, siderite, pyrite and several others of lessor volume, while preferred catalysts may include pyrite and titanium in the form of TiO₂. Oxidation reactions may break down naphthenic acids in the froth. Oxidation reactions may also attack polar compounds such that they become non-reactive and lose their hold on other compounds, such as hydrocarbons and clay, and help break the emulsion. The reactions preferably result in the froth reactor having a lower sulphur content bitumen.

According to an aspect, pyrite oxidation may be prevented or reduced in the various treatment and reactor vessels in the process, and the sulphur content may be reduced such that, as a result of the oxidation reactions in froth reactor vessel, there may be produced partially upgraded bitumen with low sulphur, and low clay and metals content. After or in combination with the reaction vessel, the hydrocarbon cleaning vessel may have a diluent added to reduce viscosity of the hydrocarbons and promote solids movement. The temperature in this vessel may be maintained at 100 to 130° C. more or less. In some cases, a centrifugal vortex motion created by a mixer may be adequate to remove remaining solids from the diluted hydrocarbons, such that a high performance, high G-force centrifuge may not be required due to a process in the Froth Reactor that frees the solids so they are no longer in an emulsified state with the bitumen particles.

According to other aspects, the produced water treatment for recycling may not be bound in a strong emulsion, but may have suspended solids and some hydrocarbons; the produced water may have below neutral pH, trace or no sodium, low hydrocarbon, high clay content, solids in the form of metal compounds, or combinations thereof; the available catalysts prevalent in oil sands ore may be used in the water treatment process; anatase may be used to provide a high quality treatment of the produced water in a pH range of 4 to 6; the application of photocatalysis (UV light) with TiO₂ may enhance the water treatment and allows faster batch reaction time and lower costs; and naphthenic acids may be destroyed and sodium surfactants may be eliminated in the extraction process allowing for continuous recycling of oil sand produced water.

According to other aspects, it may be economically viable to extract and concentrate valuable metal compounds for sale and/or for use as treatment catalysts in this or other processes, where the early removal of the large volume of sand from the oil sands ore and inhibiting the creation of an emulsion waste allow for the recovery of valuable compounds. The solids collected from the reactors vessels may include a mixture of clay, silt, and the concealed metal compounds, along with a trace of hydrocarbons, catalyst compounds may be prepared for use in a conditioning process which may include heat and acid treatments. Some catalysts may require little treatment, while others may require a special recipe of treatment. Pure pyrite may be an important catalyst for its use as a method to produce, in plain water, oxidants such as hydrogen peroxide, oxygen and superoxide. In some circumstances, it may be possible to produce a portion of or all oxidants required from the oil sands material. For example, the metal compounds may be 1% to 5% by weight of the oil sands ore, and the valuable compounds may amount to 10 to 20 kg per tonne of oil sands material. Under the method described herein, a high percentage of the valuable metals may be economically retrievable, such that they may be sold as a separate revenue stream, as they may be valuable for water treatment in other industries, or for other purposes.

In other aspects, the features described above may be combined together in any reasonable combination as will be recognized by those skilled in the art.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features will become more apparent from the following description in which reference is made to the appended drawings, the drawings are for the purpose of illustration only and are not intended to be in any way limiting, wherein:

FIG. 1 is a schematic drawing of a process for separating components from mined material.

FIG. 2 is a schematic drawing of an alternative process for separating components from mined material.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

Referring to FIG. 1 and FIG. 2, oil sands ore is conventionally surface mined with a large excavator, then conveyed to an ore conditioning crushing unit. The resulting oil sands material 10 is transferred through stream 12 to a primary separation vessel S-1 where it is mixed with water to create an oil sands slurry. The water may be preheated prior to mixing, such as in a water storage tank W-4 before being mixed with oil sands material through stream 14, or may be heated as part of the slurry in vessel S-1. As shown, water storage tank is filled from a fresh water source 16 and from the recovery of water from the separation process described herein. The source of water that is added to primary separation vessel S-1 may vary, depending on available water sources, preferences of the operator, or requirements imposed on the operator.

The oil sands slurry in primary separation vessel S-1 will generally include hydrocarbons in the form of bitumen, solids, and water. The solids will typically include sand, clay, and various other compounds, which may be in greater or lesser concentrations. In general, there may be about 100 different compounds in oil sands ore, some of which will have important impacts on bitumen and metal extraction variables, as will be described below. As used herein, the term “metal compounds” will be used in a general sense to refer to inorganic compounds found in oil sands material that typically include one or more metallic elements. This includes certain compounds that may be considered minerals, and may be contrasted to compounds that are based on metalloids and other non-metallic elements on the periodic table. In the context of the discussion herein, a reference to metal compounds is typically used in contrast to sand that is generally made up of silicates, and makes up the majority of the solids content in oil sands material. This is made apparent from the discussion herein that describes separating metal compounds from the separated sand. An example of a list of the various components, including chemically active and valuable compounds that may be found in the oil sands is provided in Table 1—Important Metals & Minerals in the Athabasca Oil Sands. This list is based on an analysis of the Athabasca oil sands, although it is anticipated that other heavy oil deposits will have similar compositions.

TABLE 1 Composition of the Athabasca Oilsands OIL SAND (OS) COMPONENT kg/ton % Notes and Comments SAND (Quartz) (SiO₂) 800 kg   80% 60-90% Sand # includes other silicates noted below CLAY- kaolinite, illite, chlorite, 50   5 Silt is included in this figure. Large variations in clay from smectite, Montmorillonite, Mica one area to the next. Clay is mostly kaolinite. BITUMEN, a complex mixture 11 6-14% Bitumen in the OS. Carboxylic Acids are a part of includes ashphaltenes, resins bitumen such as Naphthenic acid. Acids attach to clay. WATER (H₂O) 3 May be 2-8%, referred to as connate water TITANIUM bearing compounds: 3.5 0.35 Total titanium by weight ranges from .08 to 1.6% Rutile, Anatase, Brookit (TiO₂) VC 0.03 TiO₂ is photocatalytic, very creative with ROS Leucoxene (FeTiO₂) VC 0.13 Occurs in lumps, hard to concentrate amount can be high Ilmenite (FeTiO₃) V 0.02 Combined the Ti bearing compounds are the highest Limenite (FeOTiO₂) VC 0.17 volume heavy metal in the OS ZIRCON (ZrO₂ and ZrSiO₄) V 0.032 Currently mined from OS tailings by Titanium Corp. IRON OXIDES - mixed with some  7.5 kg 0.75% There is less free iron than titanium in the OS clays & integrated with other AMOUNT (%) vary by factor of 0.5 to 3 times the amount compounds shown here. Hematite (Fe₂O₃) C 0.25 Attached to other metal compounds and clay in the OS Magnetite (Fe₃O₄) C 0.25 Low % in the froth, most remains with sand in OS process, Limonite (Fe₂O₃•H₂O) C 0.12 Water soluble - mixes with sand and clay - inseparable Goethite (FeO(OH)) <0.04 Usually found with Hematite and Limonite Lepidocrocite (y-FeO(OH)) C 0.08 Forms when iron rusts underwater, concentrates in the froth Wustite (FeO) C <0.03 A geological mineral form of iron SULPHIDES: 0.30 Main source of sulfur in the Clark Hot Water Process Pyrite (FeS₂) C 0.25 Reactive - high levels of pyrite at some sites - 5% plus Calcopyrite (CuFeS₂) C 0.01 Other sulphides found in low levels: Stannite (Cu₂FeSnS₄), Iron & Zinc Sulfides (ZnS, FeS) 0.01 Bornite (Cu₅FeS₄), Galena (PbS) MANGANESE OXIDES 0.02 Concentrates in the froth Pyrolusite (MnO₂) C 0.02 Very reactive Manganese Oxide (MnO) C <0.01 This mineral form of Mang will oxidize to MnO2 MnTiO₃ may be present There is much Mn attached to other metals in the OS CARBONATES: 0.25% Large variations in carbonates 0 to 2% for the common types Calcite (CaCO₃) 0.45 Calcite is most common carbonate, some goes to the froth Siderite (FeCO₃) C <0.02 Siderite coats sand grains. Hydrophobic, 38% goes to froth Ankerite (CaFe_(x)Mg_(x)(CO₃)₂) 0.10 In Ankerite the Mg may be replaced with Mn Dolomite (CaMg(CO₃)₂) Another carbonate found in OS: Magnesite, MgCO₃ Apatite (Ca₅(PO₄)3(F)) <0.01 Mineral forms of phosphorus, Monazite ((La,Th)PO₄) 0.03 Monazite is a rare earth phosphate metal SILICATES: most in small quantities 0.13 Most silicates stay with the sand and are in the tailings Tourmaline (schorl) A cyclosilicate gemstone, mostly attaches to the froth Microcline (KAlSi₃O₈) A potassium rich igneous rock, ends up in the froth Garnet (a complex silicate) A red gemstone Staurolite ((Fe,Mg)₂Al₉Si₄O₂₃(OH)) Occurs with garnet, tourmaline & kyanite Iron Silicate (FeSiO₄) C Difficult to detect Kyanite (Al₂SiO₅) Will change to clay in surface weathering conditions Other trace elements may include nickel, vanadium, gold, silver, lithium, and other rare earth metals. V—denotes valuable metals C—denotes catalysts for ROS

In primary separation vessel S-1, a bubbling agent helps to create micro- or nano-bubbles in the slurry. The bubbling agent may be a substance added to the oils sand slurry, metal compounds that occur naturally in oil sands material 10 that act as a catalyst, or a combination of catalyst material in oil sands material 10 and an added substance. The bubbling agent may also be one or more of: a reactant, a catalyst that catalyzes the production of a reactant, or a catalyst that causes the reactant to react. The added substance may be an oxidant or a catalyst that is added to supplement the catalyst material in the oil sands material. It will be noted that the oil sands slurry is free from added surfactants and substantially free from sodium ions. The oil sands slurry may be created at or near the mining site of the oil sands material.

In one example, the bubbling agent may be an oxidant that is mixed into the oil sands slurry from a storage tank W-5. As shown in FIG. 2, the oxidant is combined with water stream 14 via oxidant stream 18 before entering primary separation vessel S-1, although oxidant may be added directly into primary separation vessel S-1 or combined with other streams or sources that may be mixed into the slurry in vessel S-1. In one example, the oxidant is hydrogen peroxide, however other oxidants may be used, such as peracetic acid, and ozone, among others. In another example, the bubbling agent may be catalyst material that is added to the slurry to catalyse a reaction that produces an oxidant substance. Preferably, the catalyst metal is pyrite, which catalyses the production of hydrogen peroxide, however other catalyst material may be used that produce different oxidant substance. Examples of other catalyst material may include calcopyrite, rutile, and anatase. Catalyst material may be present in the oil sands material 10 or may be added. Both oxidant substances and catalyst material may be added to the slurry. The oxidant reacts with catalyst material that is present in oil sands material 10. Catalyst material that is added to vessel S-1 may be metal compounds that are recovered from the oil sands material later in the process, and recycled back into vessel S-1 through stream 20.

After mixing, the oil sands slurry is conditioned to encourage at least a portion of a sand component within the oil sands slurry to settle out of the slurry in vessel S-1, and a reaction that produces bubbles to occur within the oils sands slurry, where and the bubbles interact with a hydrocarbon component of the slurry to produce a hydrocarbon froth at the top of the oil sands slurry in vessel S-1. The bubbles help to separate hydrocarbons from sand and carry the hydrocarbons to the surface of the slurry to create the hydrocarbon froth. The reaction undergone by the bubbling agent may be an exothermic reaction, and may raise the temperature of the temperature of the slurry in vessel S-1 by up to 20° C. or more. When the oxidant in the reaction is hydrogen peroxide, the temperature increase can be calculated with the following formula:

H₂O_(2(aq))+catalyst→H₂O_((l))+O_(2(g))+ΔH°

where ΔH° is the standard enthalpy of hydrogen peroxide decomposition.

As the reaction proceeds, sand will separate from the slurry and collect via gravity at the bottom of vessel S-1, a hydrocarbon froth will collect on top of the liquid in vessel S-1, and a water layer will form above the sand and below the hydrocarbon froth. It will be understood that there may be other components in each phase. For example, the layer of sand at the bottom of vessel S-1 may include a portion of the hydrocarbons. In addition to hydrocarbons, the bubbles may carry clay fines and metal particles into either the water portion or the hydrocarbon froth. As will be understood, the reaction within vessel S-1 may proceed as a batch or a continuous process based on suitable designs of vessel S-1.

Conditioning the oil sands slurry in vessel S-1 may include various steps, such as maintaining a specific temperature, maintaining a specific pH, the degree of mixing in primary separation vessel S-1, determining a suitable type and amount of bubbling agent required, using a particular design of vessel S-1, delivering air or oxygen bubbles in suitable manner (typically at the bottom of vessel S-1), and generating or inducing vibrations within vessel S-1. Daily batch testing of oil sands material 10 may be required to determine the make-up of the material that will be mixed in vessel S-1. The make-up of the oil sands material 10 may determine how the slurry will be conditioned.

Some examples of design considerations and factors that may be controlled to condition and process the oil sands material may include:

maintaining the slurry at a temperature of between 40° C. and 50° C.;

maintaining a pH that optimizes the reaction of the bubbling agent within slurry to create micro- and nano-bubbles, such as a neutral pH or slightly acidic pH to promote decomposition of hydrogen peroxide into water and oxygen bubbles;

maintaining a water to oil sands material ratio of at least about 1:1 to about 2:1, or higher if water supply is not a concern;

adding oxidant such that is makes up about 0.25% to about 1.5% of the slurry by volume;

applying steady, gentle mixing using a slow rotational and downward motion of the slurry to minimize or reduce the dispersion of clay fines in to the hydrocarbon froth;

introducing bubbles at the bottom of vessel S-1 to assist with mixing, loosening of particles, cleaning sand, and enhance the generation of the hydrocarbon froth;

designing vessel S-1 to increase retention time for the sand to fall out of the slurry, which increases the time for bubbles in the slurry to clean the sand (i.e. release the hydrocarbons from the sand, or vice versa);

applying vibrations to slurry 12, such as low frequency vibration that may promote particle movement and increase the efficiency of reactions; and

providing vessel S-1 with a water heater, such as a natural gas-powered heater, for rapid heating of water from water tank W-4.

After the sand portion has settled out of the slurry in vessel S-1, it is removed and conveyed to a sand cleaning unit S-2 via path 22 where any remaining water is drained from the sand. Other cleaning steps may also be applied to the sand in sand cleaning unit S-2 through various methods that are known in the art to produce sand that can be disposed of in a suitable manner. Sand portion may be cleaned to less than 1000 ppm hydrocarbons, in which case it may be sufficiently clean to be returned to the mining area, or used for other purposes. Sand cleaning unit S-2 may have heat exchangers (not shown) that may be used to heat incoming oil sands material 10 or water 16. Metal compounds that settle out with the sand portion, such as valuable heavy metals, may also be recovered into a container M-7.

As oil sand material 10 may be between 60% and 90% sand by weight, the departure of this large weight and volume will generally simplify the remaining extraction processes, such as by reducing subsequent handling and equipment sizing, as well as heating requirements. Operating costs and initial expense costs may thus be reduced and higher throughput rates may be achievable. Cleaned sand 24 may be reclaimed or returned to the mining site. The water portion may be removed and transferred to waste water storage tank W-1, where it may undergo further processing.

Hydrocarbon froth that collects at the top of the slurry in vessel S-1 may be removed and transferred via stream 26 to a froth treatment vessel F-1. The froth will generally be made up of hydrocarbons, water, and fine solids such as clay or metal compound fines, some of which may be recoverable and valuable. As froth is transferred and enters vessel F-1, the gaseous component is allowed to separate as the bubbles are reduced to a liquid phase. This may be encouraged by suitable agitation, heat, etc. or through use of vapour extractor S-6, as shown in FIG. 2. The gas released from the froth may be captured and reused as bubbles injected into the bottom of separator vessel S-1.

In treatment vessel F-1, the froth is suitably conditioned in order to promote a reaction with an oxidant in the presence of a catalyst to break the water-hydrocarbon emulsion within the hydrocarbon froth and allow the components to separate into a liquid hydrocarbon phase and a liquid water phase. The oxidant may be an oxidant that is present in the froth as it is removed from S-1, or an additional oxidant that is added into vessel F-1. The additional oxidant may be added directly, mixed with water and added to vessel F-1, added from tank W-5 via oxidant stream 28, or other methods. The oxidant is controlled in order to achieve a desired type and content of oxidant within vessel F-1, which may require continuous monitoring at suitable intervals. The type and content of oxidant may be determined based on the make-up of the froth or the ore at a particular mining site. Examples of oxidants that may be used include hydrogen peroxide, peracetic acid, and ozone, among others. The catalyst in F-1 may be catalyst material that is present in the froth or additional catalyst material may be added to achieve a required catalyst concentration. In some examples, the catalyst may be catalyst material that is present in large volumes in oil sand material 10, such as pyrite and titanium oxide (TiO₂), although other catalysts such as anatase, rutile, magnetite, hematite, siderite, or others may be present. Additional catalyst may also be added to tank F-1, such as from catalyst storage M-4 via stream 30. This additional catalyst may include material that has already been extracted and processed from oil sands material 10, or may be acquired from other sources. The froth may be heated prior to arriving at vessel F-1, or it may be heated in vessel F-1 to as high as 90° C. or higher.

To help promote the reaction between the oxidant and the froth, an acid may be added to the froth in vessel F-1 in order to reduce the pH to between around 4 and 6, or more preferably between around 4 and 4.5, to encourage the oxidant to react with natural emulsifiers present in the froth to break the hydrocarbon-water emulsion. Preferably, the acid is free from sulphur, and pH is controlled using acids such as acetic acid, peracetic acid, or CO₂ bubbling.

To break the emulsion, the oxidant and catalyst may result in a series of Fenton-like reactions. These reactions may attack polar molecules, such as naphthenic acid, that support the emulsion, which helps allow the hydrocarbon component of the froth to separate from the water component. The froth may also contain fine solids such as clay particles or metal compounds, and the reactions may also contribute to the separation of the fine solids from the froth. When the fine solids include pyrite, the pH may be controlled such that pyrite is a catalyst for the reaction that breaks the emulsion. When pH is maintained between around 4 and 6, pyrite does not does not break down and does not release sulphur into the hydrocarbons. Under high pH conditions, pyrite may become oxidized and would no longer be able to act as a catalyst. In addition, by adding acids that do not include sulphur the amount of sulphur content in the hydrocarbons and water that would otherwise be present is reduced. After the reactions have completed and the emulsion is broken, the pH within vessel F-1 may be higher than before the reactions took place.

As will be understood, separating the liquid hydrocarbon phase from the froth may occur in batches and a plurality of froth reaction vessels F-1 may be used in parallel to increase throughput of froth processing. The water phase separated from the froth may be transferred to waste water storage tank W-1 via stream 32, where it may undergo further treatment and processing. Solids may also be separated out after the reaction have completed and transferred to a solids vessel M-1 via path 34, where they may undergo further processing.

Once separated, the various components may be treated based on known techniques to achieve desired waste or product streams. Examples of suitable treatment processes are described below.

The separated liquid hydrocarbon phase may be transferred to a centrifugal separator F-2 through stream 36, where more solids may be removed from the liquid hydrocarbon phase. The temperature of separator F-2 may be maintained at around 100° C. to 130° C. A mixer in separator F-2 may create a centrifugal vortex motion in the hydrocarbons to remove any solids that remain. A high G-force centrifuge may not be required due to the reactions in vessel F-1 that broke the emulsion and freed the solids. The removed solids are transferred to solids vessel M-1 through path 38 and the cleaned liquid hydrocarbons are transferred to storage tank F-8 via stream 39, where it may be sent to market. As shown in FIG. 2, a diluent may be added from a diluent storage tank F-4 in order reduce the viscosity of the liquid hydrocarbon phase and enhance the removal of solids. After the liquid hydrocarbon phase has been cleaned in separator F-2 the diluent may be removed via stream F-5 and recycled in a recycler 40 into storage tank F-4 for reuse.

Solids collected in vessel M-1 may contain clay fines and metal compounds. At least a portion of the metal compounds may be catalyst material that can be conditioned for reuse in the processing of oil sands material 10. Solids may be transferred to solids processing vessel M-3 through path 42, where clay fines and silt M-6 are extracted, catalyst material is transferred to catalyst preparation vessel M-4 for further processing and storage, and other valuable metal compounds are separated and collected via M-8. Clay fines and silt M-6 may be returned to the mining site. Valuable metal compounds that have been collected from sand cleaning unit S-2 may also be transferred (not shown) into vessel M-1 to undergo similar processing, depending on what metal compounds are recovered. Catalyst material collected in catalyst storage M-4 may be conditioned for use by being treated with acid or heat, for example. Other conditioning treatments known in the art may be required, depending on the specific catalysts recovered from the oil sands material. Conditioned catalyst material may be added to water tank W-1 through path 44, mixed in the oil sands slurry via stream 20 and used as bubbling agent or catalyst in vessel S-1, or mixed with hydrocarbon froth via path 30 and used as a catalyst in vessel F-1. Valuable metal compounds may be present in the oil sands material at levels of 1% to 5% by weight, amounting to around 10 to 20 kg per tonne of oil sands material. A high percentage of the valuable metal compounds may be economically retrievable. A list of some of the valuable metal compounds that may be available for retrieval are identified in Table 1 above.

Water that is collected in waste water storage tank W-1 may contain some solids and hydrocarbons, and generally has below neutral pH, trace or no sodium content, low hydrocarbon content, high clay content and numerous metal compounds. The waste water may be treated with an oxidant such as hydrogen peroxide, peracetic acid, ozone, other oxidants, or combinations thereof. As shown in FIG. 2, waste water in W-1 may be treated with the same oxidant from oxidant storage W-5 via stream 46 that is mixed into the slurry in S-1, although the oxidant may come from other sources. Treatment of waste water may be a batch process and the amount of oxidant needed for treatment may change for different batches depending on what is present in each batch. The water may be heated as part of the processing. Waste water may be treated with catalysts obtained from oil sands material and conditioned in M-4. In one example, hydrogen peroxide and anatase may be used to treat the waste water at a pH maintained between 4 to 6 by added an acid from acid source W-a. Anatase may react with the hydrogen peroxide to produce hydroxyl radicals that react with and eliminate naphthenic acids and cause redox changes to metal compounds in the water. Tank W-1 may also be treated with ultraviolet light to so that catalyst materials undergo photocatalysis, which may lower reaction times. The mixture is then transferred to a settling vessel W-2 where a base is added from alkaline tank W-k to maintain the pH at around a neutral level. The base may cause precipitation of solids and clarification of the waste water. The clarified water may be returned to water storage tank W-4 via stream 48 for reuse in vessel S-1, or it may be returned to the environment. Precipitated solids recovered from vessel W-2 may be transferred to a solids vessel M-2 so they can be treated and recovered for addition to vessel M-3 and processed for sale or reuse. The removal of naphthenic acids and elimination of sodium in the water may allow for the continuous recycling of the water in the oil sands separation process. Hydrodynamic cavitation may be used in the processing of waste water to allow for rapid large-scale in-line continuous treatment of the waste water.

In this patent document, the word “comprising” is used in its non-limiting sense to mean that items following the word are included, but items not specifically mentioned are not excluded. A reference to an element by the indefinite article “a” does not exclude the possibility that more than one of the elements is present, unless the context clearly requires that there be one and only one of the elements.

The scope of the following claims should not be limited by the preferred embodiments set forth in the examples above and in the drawings, but should be given the broadest interpretation consistent with the description as a whole. 

What is claimed is:
 1. A method of separating solids and hydrocarbons from oil sands material, the method comprising the steps of: mixing the oil sands material with water to create an oil sands slurry, the oil sands slurry comprising hydrocarbons, sand, water and a bubbling agent, the oil sands slurry being free from added surfactants, the bubbling agent comprising metal compounds present in the oil sands material that act as a catalyst; and conditioning the oil sands slurry such that: the bubbling agent produces bubbles within the oil sands slurry; at least a portion of the sand settles out from the oil sands slurry; and the bubbles interact with the hydrocarbons to produce a hydrocarbon froth at a top of the oil sands slurry.
 2. The method of claim 1, wherein the bubbling agent further comprises an oxidant that is added to the oil sands slurry and reacts with the catalyst in the oil sands slurry.
 3. The method of claim 1, wherein the bubbling agent comprises a supplemental catalyst added to the oil sands slurry.
 4. The method of claim 1, wherein a portion of the metal compounds settle out from the oil sands slurry with the at least a portion of the sand.
 5. The method of claim 1, wherein a portion of the metal compounds are carried within the hydrocarbon froth.
 6. The method of claim 5, wherein at least a portion of the metal compounds carried within the hydrocarbon froth are recovered from the oil sands material.
 7. The method of claim 6, wherein a portion of the recovered metal compounds are catalyst material, the method further comprising the steps of: conditioning the catalyst material to improve catalytic efficiency; and mixing the conditioned catalyst material with the oil sands slurry, the hydrocarbon froth, water recovered from the oil sands slurry, or combinations thereof.
 8. The method of claim 1, further comprising the steps of: transferring the hydrocarbon froth to a treatment vessel; causing the hydrocarbon froth to release gas; adding an oxidant to the treatment vessel and reducing a pH of the hydrocarbon froth to between around 4 to 6; and causing the oxidant to react with the hydrocarbon froth to produce a phase of liquid hydrocarbons from the hydrocarbon froth.
 9. The method of claim 8, wherein the metal particles are a catalyst for the oxidant in the treatment vessel.
 10. The method of claim 1, wherein conditioning the oils sands slurry comprises maintaining a pH at or below a neutral level and maintaining a temperature of at least 40° C.
 11. The method of claim 1, wherein the oil sands slurry is at least partly heated by exothermic reactions of the bubbling agent.
 12. The method of claim 1, further comprising the step of injecting air bubbles into the oil sands slurry to enhance hydrocarbon froth production.
 13. The method of claim 1, wherein the oil sands slurry is substantially free from sodium ions.
 14. A method of separating a liquid hydrocarbon phase from a hydrocarbon froth, the hydrocarbon froth comprising water and oil sands material, the method comprising the steps of: in a treatment vessel, controlling a pH of the hydrocarbon froth to cause the hydrocarbon froth to react with an oxidant in the presence of metal compounds present in the oil sands material that act as a catalyst to break a water-hydrocarbon emulsion within the hydrocarbon froth.
 15. The method of claim 14, wherein controlling the pH comprises reducing the pH of the hydrocarbon froth.
 16. The method of claim 14, further comprising the step of reducing a gas component of the hydrocarbon froth prior to or simultaneously with causing the hydrocarbon froth to react with the oxidant.
 17. The method of claim 15, wherein the pH is reduced to between around 4 and
 6. 18. The method of claim 15, wherein an acid is added to reduce the pH, the acid being free from sulphur.
 19. The method of claim 14, further comprising the step of heating the hydrocarbon froth.
 20. The method of claim 14, wherein the metal compounds comprise fine solids in the hydrocarbon froth.
 21. The method of claim 20, wherein the fine solids comprise pyrite and at least a portion of the catalyst comprises pyrite.
 22. The method of claim 20, wherein the pH of the hydrocarbon froth is controlled to prevent pyrite from degrading to sulphur and iron.
 23. The method of claim 14, further comprising the step of separating hydrocarbons, water, and solids from the reacted hydrocarbon froth.
 24. The method of claim 23, wherein a portion of the catalyst is obtained by recycling at least portion of the separated solids into the treatment vessel.
 25. The method of claim 23, further comprising the steps of: mixing the separated hydrocarbons with a diluent to form a hydrocarbon diluent mixture; and separating any remaining solids from the hydrocarbon diluent mixture in a centrifugal separator. 